EA038706B1 - Removal of solid particles from an oil well - Google Patents

Abstract

The invention relates to a method of removing solids from an oil well using a solids removal system. In particular, the invention relates to a method for the removal of solids from a well in order to increase its production and allow the commingling of its production with the production of other wells on the same oil and/or gas production platform. This method also allows for the solid separation and washing of the removed solids.

Description

The present invention relates to a method for removing solids from an oil well using a solids removal system. In particular, the present invention relates to a method for removing solids from a well to increase its productivity and to allow production from that well to be mixed with production from other wells on the same oil and / or gas platform. This method also provides for the separation of solids and flushing of the removed solids.

Many offshore oil and gas fields are developed and operated using a multi-well platform. Typically, a drilling base plate is placed on the seabed, which includes the bore holes, and a well is drilled through each bore hole. It is not a limit to drill from 10 to 20 wells on one drilling base plate. Each well is drilled to enter a specific target reservoir or formations. The trajectory of the wells can be different, but care is taken to avoid intersection of wells with each other. The production characteristics for individual wells can be very different as each well targets different geological horizons or reservoirs or different parts of the same reservoir. Because one field has been producing for many years, some wells may drop more quickly than others as the target reservoirs of each well are depleted at different rates. Products from all wells on the base plate are collected and processed on one platform. Therefore, this platform must be operated at various production pressures and flow rates over the life of the wells it serves. In some cases, production from one or more wells is very low at much lower pressures than other wells on the same drilling platform. A common consequence of this is the build-up of solids in such low production wells. Often, after many years of production and as the reservoir becomes depleted, the reservoir pressure decreases and as a result the production rate decreases in a similar way. In addition, sand production from such a depleted reservoir may increase as the stress state in the reservoir changes due to changes in reservoir pressure. While the flow rate also decreases, the sand produced is not completely removed from the well and thus collected, and further inhibits production. In some cases, when the pressure in the reservoir decreases, water is pumped into the adjacent wells to increase the pressure in the reservoir and sweep the oil towards the producing well (s). It is not uncommon for this injected water to increase the production of sand in the production well. There are ways to remove this sand from the borehole (s), but in many cases the sand is collected and transported to shore for processing. Also, even after sand removal, the production rate and pressure of the wells (s) can be much less than other wells operating on the same platform. As a result, the production from this well (s) cannot be processed in the same way and is usually collected in reservoirs and periodically combined in batches, for example, for transportation to shore. This requires large reservoirs on the platform, which takes up very large space (or requires a large installation area), which in turn increases platform size and cost.

WO-A-2011/154919 discloses a drill rig for drilling below a particulate surface such as the seabed. The drilling rig includes drilling equipment that fluidizes surface particles using high pressure water jets and transports them to the sea surface using the lift of air bubbles that are fed into a transport pipeline.

A technical solution has been developed to overcome the limitations associated with currently used in the industry or disclosed in the prior art technologies.

The present invention provides a method for removing solids from an oil well as set forth in claim 1.

Typically, the first and second extended pipelines are coaxial. Optionally, the first extended pipeline surrounds the second extended pipeline.

Preferably, in step (b), the fluidizing tip is positioned in a first vertical position in the bed of solids, and after the solids content has been reduced, the fluidizing tip is lowered to a second vertical position in the bed of solids.

Typically, the fluidizing liquid is fed to the fluidizing nozzles at an absolute pressure of 0.05 to 0.25 MPa (0.5 to 2.5 bar). Typically, the fluidizing liquid is fed to the fluidizing nozzles at a flow rate of 50 to 250 L / min. The pressure and flow rate of the fluidizing fluid can vary depending on the depth of the well, the size of the pipeline, etc.

Typically, the fluidizing liquid is water.

Preferred embodiments of the present invention accordingly provide methods that can combine flushing low productivity well (s), separating removed solids, separating produced gas from oil, and collecting and pressurizing oil / gas produced from these wells so that oil / gas is automatically mixed with products from other wells. Such a system can provide significant improvements over the prior art.

- 1,038706 technology and allows to increase the productivity of the platform, which supports a wide range of production characteristics of individual wells.

Preferred embodiments of the present invention provide a method using a system comprising a flush or wellbore cleanout unit, a three-phase separator with a storage tank, and a pressure boosting unit.

Flushing or clearing wells of solids may include a double coiled tubing with an inner coiled tubing and an outer coiled tubing located concentrically with respect to each other. It is possible to use a single coiled tubing string while circulating back down through the annulus between the coiled tubing string and the production tubing string or casing string. The double coiled tubing string may have a fluidization jet nozzle at one end and fluid pumped down into the annulus between the inner and outer coiled tubing string passes through the jet nozzle. In operation, a double coiled tubing string is lowered into a well that needs to be flushed out to remove solids. Thereafter, fluid pumped through the fluidizing jet nozzle fluidizes the solids in the well, and the mixture of solids and fluid is flushed out of the well through the inner coiled tubing string to the surface. The washed mixture is sent to a unit for separating and washing solids.

Preferred embodiments of the present invention also provide a method that uses a three-phase separator with a storage tank and a pressure boosting unit that may be connected to a flushing or de-solids unit. In these embodiments, oil produced from the well or low pressure wells can be treated with a three-phase separator to remove solids, typically sand, and then collect the gas and oil in a fluid storage tank. The reservoir for storing the fluid can be equipped with a level sensor that measures the level of the fluid therein. The output of the level sensor can be connected to a controller, which in turn is used to control the pump to increase the pressure. The controller can maintain the level of the collected fluid at a predetermined level, for example, at the midpoint of the tank, by adjusting the pump flow rate from 0 to maximum speed or starting / stopping the pump. A pressure sensor may be provided that measures the pressure of oil during production from wells connected to a production trunk pipeline. The pressure transducer is connected to the controller, which is used to regulate the outlet pressure of the pump to increase the pressure so that the outgoing oil is at a pressure slightly higher than the pressure in the production pipeline, so that the oil passed through the three-phase separator is mixed with the oil produced from other wells of the platform. A non-return valve may be provided downstream of the pressure boosting pump that prevents the produced fluids from returning to the storage tank. The non-return valve can also serve to ensure that the oil entering the production main line is at the correct pressure, which is higher than the flow pressure in the production main line.

Preferred embodiments of this invention may provide a method for flushing wells of solids, separating and flushing said solids, collecting and pressurizing refined oil / gas produced, comprising the steps of:

1) Lowering into the well a double coiled tubing string containing concentrically spaced inner and outer coiled tubing strings with a jet nozzle for fluidization.

2) Pumping the fluid down into the annulus between the concentrically located inner and outer strings of coiled tubing to fluidize solids into which the jet tip is lowered.

3) Collect leached solids and fluidizing fluid that exits upward through the inner coiled tubing string and direct them to a solids separation and washing plant.

4) After the well has been cleared of solids and begins to flow oil again, remove the coiled tubing from the well and route the produced oil (which contains some of the solids) to a three-phase separator with a storage tank.

5) Collection of the produced oil, which is purified from solids and gas in a storage tank.

6) Using tank fluid level measurement to turn on a pressure boosting pump that moves oil out of the storage tank as soon as the level rises above the set tank level, and stopping the pump as soon as the fluid level falls below the set level.

7) The use of pressure measurement in the main oil production trunk pipeline to regulate the outlet pressure of oil from the storage tank in the pump to increase the pressure to a pressure that is higher than the pressure in the main pipeline, so that oil transferred from the storage tank can be mixed with the main product with platforms.

In the following, embodiments of the present invention are described in more detail, by way of example only, with reference to the accompanying drawings, where

- 2 038706 in Fig. 1 is a schematic side view of an oil and / or gas production platform for applying the method of the present invention thereto;

in fig. 2 is a schematic side view of a solids removal system for use in a method according to one embodiment of the present invention;

in fig. 3 is a schematic end view of a fluidization jet nozzle in the solids removal system of FIG. 2, and in FIG. 4 is a schematic side view of a three-phase separator and pressurizing device for use in a method according to one embodiment of the present invention.

FIG. 1 is a schematic diagram of an oil and / or gas production platform 103 with a drilling baseplate 104 that has four wells 105 drilled into different reservoirs 106 and 109. The seabed is denoted 101 and the sea surface is denoted 102. FIG. 1 all four wells are producing wells, however well 107 was depleted faster than the others and as a result its production rate is lower and solids removed, usually sand, are not completely removed from the well, but subsided as shown as a layer of solids indicated at 108. Without any intervention to clean up these solids, well 107 will cease to flow completely, resulting in lower overall platform productivity. In addition, since well 107 was depleted more quickly, the pressure in formation 109 is lower than in other formations 106, so the oil produced from well 107 is at a lower pressure. As a result, the production from this well 107 cannot be directly mixed with the production of other wells producing from 106, as this will cause the flow from them to flow down into the well 107 and into the depleted formation 109.

Various embodiments of the present invention are described below that can overcome or eliminate such limitations.

FIG. 2 and 3 show a schematic diagram of a solids removal system 200 that can be used to restore the well 107 shown in FIG. one.

System 200 includes a fluidizing jet nozzle 204 configured to be disposed in a solids layer 203 at the bottom of well 201. A first long conduit 207 extends from nozzle 204 and is configured to connect to a source (not shown) of a fluidizing liquid such as water. A second extended conduit 208 extends from tip 204 and is configured to be connected to a solids separation unit (shown in FIG. 4) located above well 201. The tip 204 includes fluid nozzles 209 in fluid communication with the first extended conduit 207, and an inlet 206 for a fluidized mixture of solids in a fluidizing liquid in fluid communication with the second extended conduit 208. The first and second extended conduits 207, 208 are coaxial and the first extended conduit 207 annularly surrounds the second extended conduit 208.

Shown in FIG. 2, well 201 has a reduced productivity so that solids are no longer removed in the stream and accumulates in the solids layer 203 over a period of time. A coiled tubing string 202, consisting of two concentric pipes defining a first longitudinal conduit 207 and a second longitudinal conduit 208, is lowered into a well 201 such that a fluidizing jet nozzle 204 at its lower end is positioned within the solids bed 203. In this embodiment, as shown in FIG. 2, the end of the spray tip 204 typically has eight fluid nozzles 209. One of ordinary skill in the art will appreciate that the number of nozzles 209 can be less or more than this number, and can be sized to provide suitable jet and fluidizing properties.

The double concentric coiled tubing 202 has an outer annular conduit 207 defining a flow inlet and an inner circular conduit 208 defining an outlet flow. A fluid, usually water, is pumped down annular conduit 207 and is jetted through nozzles 209 into the solids bed 203 as indicated by arrows 205. This fluidizes the solids in the vicinity of the jet nozzle 204. The fluidized mixture is discharged in the form of jets of fluid and solids exits through inner circular conduit 208 of double coiled tubing 202 as indicated by arrows 206.

The fluidizing jet tip 204 is disposed in a first vertical position in the solids bed 203. After the solids content of the mixture has been reduced, the fluidization jet tip 204 can be lowered to a second vertical position in the solids bed 203.

Typically, the fluidizing liquid is fed to the fluid nozzles 209 at 0.05 to 0.25 MPa (0.5 to 2.5 bar) absolute and / or at a flow rate of 50 to 250 L / min. The pressure and flow rate of the fluidizing fluid can vary depending on the depth of the well, the size of the pipeline, etc.

As the layer 203 of solids is removed, the coiled tubing 202 is gradually lowered further.

- 3,038706 into well 201 until the solids layer 203 has been removed. Wellbore solids

201 can be coated with hydrocarbons so that they must be separated and cleaned before they can be disposed of in a suitable manner. This is preferably achieved using the apparatus and method disclosed in UK patent application 1420257.6.

Once the solids layer 203 has been removed, well 201 is no longer plugged and can be re-connected as it can produce more oil than before the recovery process. However, those skilled in the art will appreciate that due to the depletion of the formation, production from this well will occur at a lower pressure than other wells on the same production platform. Consequently, solids are likely to begin to accumulate again, but this will take some time and, within a certain period of time, reach economically viable additional oil production. In addition, further recovery can be performed repeatedly using the same process as described in this document.

FIG. 4 is a schematic diagram of a three-phase separator and pressurizing device for use in the process, which represent another embodiment of this invention.

FIG. 4 shows an apparatus for separating solids from a hydrocarbon-containing fluid produced by an oil and / or gas production facility. The equipment includes three wells 300, referred to as wells 1, 2 and 3, connected to a primary production pipeline in the form of a common trunk pipeline 309. It is understood that the number of wells 300 may be more or less in any particular implementation.

The primary production conduit 309 has an upstream portion 320 and a downstream portion 322. At least one three-way valve 301 is connected to the upstream portion 320. The valve 301 has a first outlet 324 in fluid communication with the primary a production line 309, a second outlet 326 in fluid communication with a solids separation unit, generally configured as 328, and an inlet 330, configured to be connected to a well 300 for oil and / or gas production. The first and second outlets 324, 326 of valve 301 are selectively coupled to an upstream end 320 or to a solids separation unit 328. The valve 301 or each of the valves 301 is operable to select between the respective first and second outlets 324, 326.

At least one valve 301 includes three-way valves 301 connected to an upstream portion 320. Each three-way valve 301 has a first outlet 324 in fluid communication with the primary production conduit 309, a second outlet 326 in fluid communication medium with a block 328 separating solids, possibly through an on-off valve, and an inlet 330, in operation, connected to the well 300 for oil and / or gas production. The first and second outlets 324, 326 of each three-way valve 301 are selectively coupled to the upstream portion 320 or to the solids separation unit 328, and the three-way valves 301 are individually actuated to select between the respective first and second outputs 324, 326.

The pressure sensor 344 can sense the pressure of the fluid at the inlet 330 of the valve. A valve control device 344 may be provided to switch inlet 330 into fluid communication with second outlet 326 when the sensed fluid pressure is below a predetermined pressure threshold or when the pressure difference between the sensed pressure and the pressure in the primary production conduit 309 is greater than a predetermined minimum pressure difference. ...

The solids separation unit 328 has a common manifold 310 to which each outlet 326 is connected directly or via an intermediate conduit and / or valve interconnect system.

The solids separation unit 328 includes at least one solids separator 303, 304 and has a first solids outlet 306 and a second fluid outlet 332. A second fluid outlet 332 is in fluid communication with an inlet 334 of a fluid separator 305 having a liquid outlet 336 and a gas outlet 338. The liquid outlet 336 is in fluid communication with the downstream portion 332 through a return line 340.

A controller 313 is provided to control the flow of liquid from the fluid separator 335 to the downstream portion 322 through the return line 340.

Disposed in the return line 340 is a pressure boosting pump 308 for pressurizing the liquid in the return line 340 and pumping the pressurized liquid in the return line 340 away from the fluid separator 305 to the downstream portion 322.

The controller 313 is configured to control one or more of the output pressure of the pump 308, the flow rate of the pump 308, and the on / off function of the pump 308, in any combination.

- 4 038706

In this embodiment, the controller 313 is configured to adjust the outlet pressure of the pump 305 to be higher than the liquid pressure in the primary production conduit 309, preferably by a predetermined minimum pressure difference.

A pressure sensor 312 for measuring the pressure of the liquid in the primary production line 309 is coupled to the controller 313 to provide a pressure signal to the controller 313 to regulate the output pressure of the pump 305.

A reservoir sensor 311, preferably a liquid level sensor, measures the amount of liquid in the reservoir 342 of the fluid separator 305. The controller 313 provides a control signal to control the flow of liquid from the fluid separator 305 to the downstream portion 322 through the return line 340 when the amount of liquid exceeds a predetermined threshold. The control signal is configured to induce or allow a flow of liquid from the fluid separator 305 to the downstream portion 322 when the liquid level in the reservoir 342 of the fluid separator 305 exceeds a predetermined level threshold. The control signal may maintain the liquid level in the reservoir 342 of the fluid separator 305 above a predetermined minimum level threshold and / or below a predetermined maximum level threshold.

The pump 308 may be configured to restrict the flow of liquid from the downstream portion 322 to the fluid separator 305 through the return line 340, for example by providing a non-return structure. In the illustrated embodiment, a non-return valve 314 is disposed in the return line 340 between the pump 308 and the primary production line 309 to restrict, preferably prevent the flow of liquid from the downstream portion 322 to the fluid separator 305 through the return line 340. The non-return valve 314 can be self-adjusting as such that it opens to allow forward flow therethrough at a given pressure drop across the non-return valve 314. Alternatively, the controller 313 may be configured to regulate the non-return valve to open it to allow flow through it in the forward direction at a given pressure in the return line 340 upstream of the non-return valve 314 or at a predetermined differential pressure across the non-return valve 314. The controller 313 may be configured to regulate the non-return valve 314 to open it to allow black to flow. Without it, forward flow when the target return line pressure 340 is upstream of non-return valve 314 above the liquid pressure in the primary production line 309 by a predetermined minimum pressure difference.

A gas compressor 316 is optionally coupled to the gas outlet 338 of the fluid separator 305 to provide compressed gas from the fluid separator 305. Typically, the outlet 307 of the gas compressor 316 is connected to a gas production line (not shown) of the gas production equipment. The controller 313 may be configured to regulate the outlet pressure of the gas compressor 316 to be higher than the gas pressure in the gas production line, possibly by a predetermined minimum pressure difference.

Therefore, settings are provided for the three-way valves 301 and the two-position valves 302 to direct flow from any well or group of wells 300 to either the main production line 315 or through the second line 310 to the three-phase separator and pressure booster. The pressure in the main line 310 can be lower than the pressure in the production line 309, for example, equal to atmospheric pressure. If the flow from well 1 exits a depleted formation operated at a lower pressure and also carries sand as described in other embodiments of this invention, then the flow from that well is no longer directed to the main production pipeline 309, but is directed through the pipeline 310 to separator and pressure boosting system. This is achieved by adjusting the valve 301 in well 1 and opening the valve 302 of well 1 so that the flow from the well no longer enters the main production pipeline 309, but is directed to the pipeline 310.

The stream from the main line 310 is initially directed to a first solids separation unit 303, as shown in FIG. 4. Preferably, the separator is as described in UK Patent Application 1420257.6, however, those skilled in the art will appreciate that it could be another type of solid separator. The fluid from which the solids have been removed exits the top of the unit 303 and is directed to the second solids separator 304. In some implementations, one solids separator will suffice, but in other implementations more than two separators may be required, but preferably a dual solids separator system is used. The solids separated by 303 and 304 are collected at the bottom of the separators and leave the system as indicated by arrow 306. Fluid further de-solids exits 304 and is fed to the oil / gas separator and reservoir 305. storage fluid shown in FIG. 4.

The gas separated from the stream exits 305 from the top, as indicated by 307, and is collected

- 5,038706 or flared in a well known manner. Optionally, the compressor 316 is used to pressurize the gas to that of another production gas at the platform such that the collected gas is mixed with the main production gas.

The separated oil is collected at the bottom of a reservoir 305 which is equipped with a level sensor 311 as described in other embodiments of this invention and schematically illustrated. Also, the pressure in the main production pipeline is measured using the pressure sensor 312. The fluid level in both the oil / gas separator and the fluid storage tank 305 and the pressure measured in the main line 309 are connected to the controller 313. Additionally, a pressure boosting pump 308 is provided, also connected to the controller 313. The controller is programmed as follows. to use these measurements to maintain the level in the storage tank 305 at a predetermined level, for example, in the middle of the tank. As soon as the level of the fluid in the storage tank 305 reaches a certain level above the middle, the controller 313 drives the pump 308 to increase the pressure, and the pressure of the fluid pumped from the storage tank 305 is increased to a pressure that is higher than the pressure of the main production stream in main line 309, measured by pressure sensor 312. The pressurizing pump 308 continues to reduce the liquid level in the storage tank 305 until it reaches a predetermined level below the middle, at which point in time the pressurizing pump 308 stops pumping. A non-return valve 314 prevents production fluid from flowing back towards the three-phase separator. This non-return function may be inherent in the pressure boosting pump 308 as such. When pump 308 is turned off to pressurize, the level in storage tank 305 begins to rise again as production from well 1 continues and production is passed through separators 303, 304. Once the liquid level in storage tank 305 rises to a predetermined level above midpoint again , the pump to increase the pressure is activated and the cycle is repeated. The controller 313 can be associated with a display device (not shown) where measured parameters and pump status can be displayed. Preferably, the pressure boosting pump 308 is automatically operated as described, but can be manually turned on and off by an operator who acts in response to the displayed measured data.

In a simplified form, the pressure sensor 312 is not required, and the pump 308 increases the pressure of the oil removed from the storage tank 305 by pumping it out from the non-return valve 314 to increase the pressure. As soon as the pressure of this oil rises above the oil pressure in the production line 309, the non-return valve 314 is opened and the pressurized oil from the storage tank 305 enters the main production stream 315. In this case, the pump 308 for pressurization is controlled by the controller 313, which uses only the measurement data of the fluid level in the storage tank 305 provided by the sensor 311. B in this embodiment, the pressure sensor 312 is omitted in FIG. 4, and controller 313 has one input from sensor 311, and the output from 313 turns on and off pump 308 to increase pressure or regulates its speed, as shown in FIG. 4 and previously described using the fluid level in the storage tank 305.

The product collected in the storage tank 305 from the low pressure well 1 is first cleaned of solids and gas as described, and then pressurized to such a pressure that it can be mixed with the product from other wells, for example, wells 2 and 3, in order to to contribute to the overall performance of the platform, as illustrated at 315.

Using the apparatus and method of the preferred embodiment described herein, a low-yield oil well or group of oil wells that have been adversely affected by the build-up of solids in the well or wells can be recovered through solids removal and cleaning. In extreme situations, the well or wells may even stop producing oil due to this accumulation and, after recovery, may return to oil production. The production from the low production well or wells can be cleaned of any amount of removed solids, which are usually sand, and any amount of produced gas. The produced oil is then collected and then pressurized to a higher pressure so that it can be mixed with oil produced from other wells on the same platform. Such a system will allow these wells to continue producing oil, albeit at a low rate, and contribute to an increase in the overall platform productivity. It also extends the lifespan of the platform and provides significant advantages over current practice.

The present invention described in the appended claims may be embodied in many different forms and should not be limited to the embodiments set forth herein; on the contrary, these embodiments are presented so that this description is detailed and complete and fully conveys to those skilled in the art the concept of the invention as defined in the appended claims.

Claims (5)

CLAIM 1. A method for removing solids from an oil well using a solids removal system, wherein the solids removal system (200) includes a fluidizing jet tip (204) configured to be placed in a layer (203) of solids at the bottom of the well (201 ), a first long line (207) extending from a tip (204) and connected to a source of fluidizing liquid, a second long line (208) extending from a tip (204) and connected to a solids separation unit (328), where the tip (204 ) includes fluid nozzles (209) in fluid communication with the first extended pipeline (207), and an inlet (206) for a fluidized mixture of solids in a fluidizing liquid, in fluid communication with the second extended pipeline (208) where the fluid discharge nozzles (209) surround the inlet (206); the method contains the following stages: a) placing the fluidizing jet tip (204) in the solids bed (203) at the bottom of the wellbore (201), where the fluid nozzles (209) face downward; b) feeding the fluidizing liquid at an absolute pressure of 0.05 to 0.25 MPa (0.5 to 2.5 bar) and a flow rate of 50 to 250 l / min through the first long line (207) extending upward from the tip ( 204) to nozzles (209) for discharging fluid; c) discharging downward jets of fluidizing liquid from the solids fluidizing nozzles (209) near the tip (204) within the fluidizing fluid to form a fluidized mixture of solids in the fluidizing fluid; d) removing the fluidized mixture from the bed (203) of solids through an inlet (206) of a tip (204) surrounded by fluid nozzles (209), the inlet (206) in fluid communication with a second long conduit (208), extending upward from the tip (204), and f) transporting the fluidized mixture through a second long line (208) to a solids separation unit (328) located above the well (201). 2. A method according to claim 1, wherein the first and second extended pipelines (207, 208) are coaxial. 3. The method of claim 2, wherein the first longitudinal conduit (207) surrounds the second longitudinal conduit (208). 4. A method according to any one of claims 1 to 3, wherein in step (a) the fluidizing tip (204) is positioned in a first vertical position in the solids bed (203) and after the solids content has been reduced, the tip ( 204) for fluidization is lowered to a second vertical position in the solid bed (203). 5. A method according to any one of claims 1 to 4, wherein the fluidizing liquid is water.